Petroleum is found in subterranean formations or reservoirs in which it has accumulated, and recovery is initially accomplished by pumping or permitting the petroleum to flow to the surface of the earth through wells drilled into the subterranean formation for that purpose. Petroleum can be recovered from subterranean formations only if certain conditions are satisfied. For example, there must be an adequately high concentration of petroleum in the formation, and there must be sufficient porosity and permeability or interconnected flow channels throughout the formation to permit the flow of fluids therethrough if sufficient pressure is applied to the fluids. Furthermore, the formation petroleum viscosity must be sufficiently low that petroleum will flow through the flow channels if pressure is applied thereto. When the subterranean petroleum-containing formation has natural energy present in the form of an underlying active water drive, or solution gas, or a high pressure gas cap above the petroleum-saturated zone, this natural energy is utilized to recover petroleum. This phase of oil recovery is referred to as primary recovery. When this natural energy source is depleted, or in the instance of those formations which do not originally contain sufficient natural energy to support primary recovery operations, some form of enhanced recovery or supplemental recovery process must be applied to the formation. Supplemental oil recovery is sometimes referred to in the literature as secondary or tertiary recovery, although in fact it may be primary, secondary or tertiary in sequence of employment.
Although waterflooding or water injection is the simplest and most widely used form of oil recovery, it is only partially effective because water does not displace petroleum efficiently. Persons skilled in the art of oil recovery have recognized this inefficiency of waterflooding, and it has been proposed in the literature to inject a solvent for petroleum into the formation to reduce the viscosity of the naturally occurring petroleum, followed by injecting a drive fluid, such as water or natural gas, in order to recover a higher percentage of the formation petroleum than is possible utilizing water or gas alone.
A particularly promising type of miscible flooding which has been applied successfully to reservoirs having substantial vertical thickness, is referred to as vertically downward moving, miscible blanket flooding. This type of oil recovery is especially suitable for use in thick reservoirs, e.g., petroleum reservoirs having vertical thickness in excess of 50 feet or more. In miscible blanket flooding, a solvent, e.g., a material which is miscible under reservoir conditions with formation petroleum, is injected into the upper portion of the petroleum reservoir. After a predetermined volume of solvent is injected, sufficient to form a thin layer or blanket on the top of the oil-saturated portion of the formation, a drive fluid such as lean or dry gas, e.g., natural gas or methane, is injected into the upper portion of the formation in order to displace the slug or blanket of solvent vertically downward. The idealized version of downward miscible blanket flooding contemplates the establishment of a discrete, relatively thin layer of solvent which is spread completely across the top of the petroleum formation, with the layer of solvent then being displaced downward in a substantially piston-like manner by the subsequently-injected dry gas. Oil production is ordinarily taken from wells completed in and in fluid communication with the bottom of the petroleum-containing formation. Drive gas will displace liquid solvent and petroleum efficiently only if it is displacing the solvent and petroleum vertically downward, thereby employing gravitational forces to stabilize the process and avoiding viscous fingering as is sometimes encountered when gas injection is applied to a formation in a horizontally moving displacement process.
Although in this simplified description, the solvent action is obtained from the intermediate (C.sub.2 -C.sub.9) hydrocarbon components injected for the purpose of functioning as a solvent, and the gas is described only as an inert displacing agent, in fact a multicomponent mixture is formed in the formation, comprising the heavy components, e.g., the hydrocarbon or petroleum naturally occurring in the formation, the intermediate component hydrocarbon species which is the liquid solvent injected into the formation, and the drive gas which may be considered to be essentially pure methane. Since methane is substantially less expensive than the intermediate component hydrocarbon, e.g., LPG or liquified petroleum gas or other hydrocarbons which may be injected for the purpose of functioning as a solvent or miscible displacement agent for petroleum, it is highly desirable to operate under conditions where miscibility is achieved between components of the naturally-occurring petroleum, the injected solvents, and the injected drive gas, utilizing the smallest volume possible of solvent. To accomplish this, it is frequently necessary to raise the pressure existing in the formation where it is desired to obtain a condition of miscibility.
In field application of the above process, considerable difficulty has often been encountered in obtaining sufficient increase in formation pressure to achieve the desired condition of miscibility. This sometimes results from inherent low pressure in the reservoir, or the presence of a high gas saturation of the oil zone, the presence of a substantial size gas cap, or the presence of a low pressure aquifer below the petroleum-saturated interval which is of much greater size than the petroleum formation. When these conditions are encountered, injection of substantial quantities of gas, even at maximum injection rates, raising the pressure of the reservoir sufficiently to achieve miscibility between oil and the injected miscible fluids can seldom be accomplished. Accordingly, there is a substantial problem in applying the miscible oil recovery method described above to subterranean petroleum-containing formations because of the inability to raise the formation pressure substantially to attain miscibility with the injected miscible displacing fluids.